Gas-lift system with paired controllers

ABSTRACT

Systems and methods for controlling operation of a well, of which the method includes receiving an operation setting for operation of a system that provides lift gas into and produces gas from the well, monitoring operation of the system using a first controller, determining, using the first controller, that the system is not operating at the operation setting, and in response to determining that the system is not operating at the operation setting, sending, using a two-way communication link from the first controller to a second controller, a control signal to the second controller. The control signal is configured to cause the second controller to modify an operation of a compressor of the system.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application is a continuation of application Ser. No. 16/011,071filed Jun. 18, 2018, now U.S. Pat. No. 11,199,081, which claims priorityto U.S. Provisional Application No. 62/522,362 filed on Jun. 20, 2017,the entirety of which is hereby incorporated by reference.

BACKGROUND

Gas lift plungers are employed to facilitate the removal of gas fromwells, addressing challenges incurred by “liquid loading.” In general, awell may produce both liquid and gaseous elements. When gas flow ratesare high, the gas carries the liquid out of the well as the gas rises.However, as the pressure in the well decreases, the flowrate of the gasdecreases to a point below which the gas fails to carry the heavierliquids to the surface. The liquids thus fall back to the bottom of thewell, exerting back pressure on the formation, and thereby loading thewell.

Plungers alleviate such loading by assisting in removing liquid and gasfrom the well, e.g., in situations where the ratio of liquid to gas ishigh. For example, the plunger is introduced into the top of the well.One type of plunger includes a bypass valve that is initially in an openposition. When the bypass valve is in the open position, the plungerdescends through a tubing string in the well toward the bottom of thewell. Once the plunger reaches the bottom of the well, the bypass valveis closed. A compressed gas is then introduced into the well, below theplunger. The compressed gas lifts the plunger within the tubing string,causing any liquids above the plunger to be raised to the surface.

A compressor at the surface pressurizes the gas that is introduced intothe well. As will be appreciated, the operation of the plunger is moreefficient when the compressed gas is not introduced into the well as theplunger is descending. However, releasing the compressed gas into theatmosphere as the plunger descends generates a loud noise that may beharmful to the ears of those around. In addition, releasing thecompressed gas into the atmosphere may also raise environmentalconcerns. Another option would be to turn the compressor off every timethe plunger is descending; however, frequent switching of the compressoron and off may be inefficient and may reduce the lifespan of thecompressor.

Furthermore, in some cases, the operation of the compressor may need tobe adjusted to maintain efficient production. For example, the flowrateof the compressed gas may eventually become too low for the wellconditions. In such case, the cycle time for the plunger may become toolong, and thus a higher gas flowrate may be called for. Typically, thisinvolves manual reconfiguration of the compressor.

SUMMARY

Embodiments of the disclosure may provide a method for controllingoperation of a well, of which the method includes receiving an operationsetting for operation of a system that provides lift gas into andproduces gas from the well, monitoring operation of the system using afirst controller, determining, using the first controller, that thesystem is not operating at the operation setting, and in response todetermining that the system is not operating at the operation setting,sending, using a two-way communication link from the first controller toa second controller, a control signal to the second controller. Thecontrol signal is configured to cause the second controller to modify anoperation of a compressor of the system.

Embodiments of the disclosure may also provide a system including acompressor configured to compress gas, a compressor controllerconfigured to control an operation of the compressor, a wellheadconfigured to receive compressed gas from the compressor, a wellheadcontroller coupled to the wellhead and configured to measure one or moreoperation settings, and a two-way communication link between thewellhead controller and the compressor controller. The wellheadcontroller is configured to send one or more control signals to thecompressor controller via the two-way communication link, and thecompressor controller is configured to adjust the operation of thecompressor in response to the one or more control signals.

Embodiments of the disclosure may also provide a method for controllingoperation of a well. The method includes introducing a gas into aseparator. The method also includes removing particles from the gasusing the separator to produce a clean gas. The method also includesintroducing the clean gas into a compressor. The method also includesdetermining when a plunger is at a predetermined position in the well.The method also includes transmitting a first signal to a controllerwhen the plunger is at the predetermined position in the well. Themethod also includes causing the compressor to not compress the cleangas flowing therethrough in response to the first signal. The methodalso includes actuating a valve into a first position in response to thefirst signal, thereby allowing the plunger to descend in the well. Themethod also includes transmitting a second signal to the controller apredetermined amount of time after the plunger is determined to be atthe predetermined position in the well. The method also includescompressing the clean gas using the compressor in response to the secondsignal. The method also includes actuating the valve into a secondposition in response to the second signal, thereby causing the plungerto ascend in the well.

BRIEF DESCRIPTION OF THE DRAWINGS

The accompanying drawings, which are incorporated in and constitute apart of this specification, illustrate embodiments of the presentteachings and together with the description, serve to explain theprinciples of the present teachings. In the figures:

FIG. 1 illustrates a schematic view of a system for operating a gas-liftplunger in a well, according to an embodiment.

FIG. 2 illustrates a flowchart of a method for operating the gas-liftplunger in the well, according to an embodiment.

FIG. 3 illustrates a flowchart of another method for operating thegas-lift plunger in the well, according to an embodiment.

FIG. 4 illustrates a flowchart of a method for controlling a gas-liftsystem, according to an embodiment.

it should be noted that some details of the figure have been simplifiedand are drawn to facilitate understanding of the embodiments rather thanto maintain strict structural accuracy, detail, and scale.

DETAILED DESCRIPTION

In general, embodiments of the present disclosure may provide a gas-liftwell production system, and method for operating such system, which mayinclude paired controllers, optionally with remote configuration access.The system may generally include a compressor, with a compressorcontroller, and a wellhead (i.e., equipment positioned at the top of awell), with a wellhead controller. The wellhead controller and thecompressor controller may be in two-way communication with one anothersuch that they are able send control and/or status signals therebetween.The wellhead controller may determine when one or more system operatingcharacteristics are suboptimal (e.g., plunger cycle time is too long).In response, the wellhead controller may communicate a signal indicativeof this determination to the compressor controller.

The compressor controller may, in response, modulate the compressor'soperating parameters (e.g., speed and/or suction pressure) and/or anyother system parameters (e.g., diverter valve position) to adjust theflowrate of injection gas to the well. The compressor controller and/orthe wellhead controller may be configured to provide acknowledgmentsignals in response to receiving a signal from the other controller,and/or may provide status update signals (e.g., a “heartbeat”), suchthat both controllers are “aware” that the other controller is onlineand can ascertain and take mitigating steps (e.g., initiate alarms,shutdown, etc.) when the other controller goes offline. This and othervarious aspects of the present disclosure may be accomplished in avariety of different ways, a few examples of which are provided below.

In some embodiments, such systems with paired controllers may be able tochange the state of the compressor (e.g., speed and/or suction pressure)This may reduce wear on the machine, save fuel, and eliminate or atleast reduce consumption of purchase gas (gas sent to and then boughtback from the well owner). Further, such systems may be implemented ingas-lift wells and in plunger-lift wells.

Reference will now be made in detail to embodiments of the presentteachings, examples of which are illustrated in the accompanyingdrawing. In the drawings, like reference numerals have been usedthroughout to designate identical elements, where convenient. In thefollowing description, reference is made to the accompanying drawingthat forms a part thereof, and in which is shown by way of illustrationone or more specific example embodiments in which the present teachingsmay be practiced.

Further, notwithstanding that the numerical ranges and parameterssetting forth the broad scope of the disclosure are approximations, thenumerical values set forth in the specific examples are reported asprecisely as possible. Any numerical value, however, inherently containscertain errors necessarily resulting from the standard deviation foundin their respective testing measurements. Moreover, all ranges disclosedherein are to be understood to encompass any and all sub-ranges subsumedtherein.

FIG. 1 illustrates a schematic view of a system 100 for operating agas-lift plunger 170 in a well 160, according to an embodiment. Althoughillustrated as a plunger-lift system, it will be appreciated that thepresent system 100 may be employed in a gas-lift application. The system100 may include a driver 110, such as an internal combustion engine orelectric motor, a pressure vessel 120, and a compressor 130. Whenactive, the driver 110 drives the compressor 130, such that thecompressor 130 is capable of compressing gas.

The pressure vessel 120 may be a separator (e.g., a scrubber). Thepressure vessel 120 may have one or more inlets (two are shown: 122,124) and one or more outlets (one is shown: 126). The pressure vessel120 may be configured to receive a gas through the first inlet 122, thesecond inlet 124, or both inlets 122, 124. Although not shown, in atleast one embodiment, the pressure vessel 120 may include a singleinlet, and the two inlet flows may both enter the pressure vessel 120through the single inlet (e.g., via a T-coupling coupled to the singleinlet). The pressure vessel 120 may then separate (i.e., remove)particles from the gas to clean the gas. In at least one embodiment, thepressure vessel 120 may be a gravity-based separator, such that theseparation may be passive, allowing the denser solid particles to fallto the bottom of the pressure vessel 120. The clean gas may then exitthe pressure vessel 120 through the outlet 126. The pressure vessel 120may have an internal volume ranging from about 0.04 m³ to about 0.56 m³,or more.

The compressor 130 may include an inlet 132 that is coupled to and influid communication with the outlet 126 of the pressure vessel 120. Thegas that flows out of the outlet 126 of the pressure vessel 120 may beintroduced into the inlet 132 of the compressor 130, as shown by arrows128. The compressor 130 may be configured to compress the gas receivedthrough the inlet 132. The gas may exit the compressor 130 through anoutlet 134 of the compressor 130. The compressor 130 may be areciprocating compressor. In other embodiments, the compressor 130 maybe a centrifugal compressor, a diagonal or mixed-flow compressor, anaxial-flow compressor, a rotary screw compressor, a rotary vanecompressor, a scroll compressor, or the like.

A first valve (also referred to as an “unloader valve”) 140 may becoupled to and in fluid communication with the outlet 134 of thecompressor 130. When the first valve 140 is in a first position, the gasmay flow through the first valve 140 and be introduced back into thepressure vessel 120, as shown by arrows 136. For example, the gas may beintroduced into the pressure vessel 120 through the second inlet 124.When the first valve 140 is in a second position, the gas exiting thecompressor 130 may flow through the first valve 140 and be introducedinto a well 160 (as shown by arrows 138) and/or a sales line 146 (asshown by arrows 148). As used herein, a “sales line” refers to apipeline where the gas is metered and sold.

A second valve (also referred to as a “diverter valve”) 142 may becoupled to and in fluid communication with the outlet 134 of thecompressor 130 and/or the first valve 140. As shown, the second valve142 may be positioned downstream from the first valve 140. When thesecond valve 142 is in a first position (e.g., “open”), the gas from thecompressor 130 may flow through the second valve 142 and be introducedinto the sales line 146, as shown by arrows 148. The gas may not flowinto the well 160 when the second valve 142 is in the first position.When the second valve 142 is in a second position (e.g., “closed” or“shut”), the gas from the compressor 130 may flow through the secondvalve 142 and be introduced into the well 160, as shown by arrows 138.The gas may not flow into the sales line 146 when the second valve 142is in the second position.

A third valve 144 may be coupled to and in fluid communication with thesecond valve 142. The third valve 144 may be positioned between thesecond valve 142 and the well 160 (i.e., downstream from the secondvalve 142). The third valve 144 may be a check valve or a diverter valvethat allows the gas to flow through in one direction but not in theopposing direction. For example, the third valve 144 may allow the gasto flow from the compressor 130 into the well 160, but not from the well160 into the sales line 146. Optionally, another check (or diverter)valve may be positioned between the first valve 140 and the second valve142, so as to prevent backflow of gas into the first valve 140.

A compressor controller 150 may be coupled to the compressor 130, thefirst valve 140, the second valve 142, or a combination thereof. Thecompressor controller 150 may be configured, among other things, tocontrol one or more operating parameters of the compressor 130. Forexample, the compressor controller 150 may be configured to adjust thespeed (or RPM—revolutions per minute) of the compressor 130. Control ofthe speed of the compressor 130 may be accomplished in a variety ofways, e.g., by communication with the driver 110, power source, and/ordriveline components between the driver 110 and the compressor 130.

Additionally or alternatively, the compressor controller 150 may beconfigured to adjust the suction pressure of the compressor 150. Forexample, adjustment of the suction pressure may be achieved byselectively opening and closing two or more pilot valves at the inlet132. For example, if two pilot valves are provided, one may operate at(e.g., “correspond to”) a relatively high suction pressure, while theother may operate at (e.g., “correspond to”) a relatively low suctionpressure. Thus, the suction pressure of the compressor 130 may bedetermined by which of the pilot valve is open and which is closed. Insome embodiments, more than two such inlet valves may be provided,thereby allowing for more than two choices of suction pressures. Inother embodiments, one or more such inlet valves may be provided with avariable position, which may allow for many different setpoints(sometimes referred to as “infinite” control) for the suction pressure.

Further, as also discussed in greater detail below, the compressorcontroller 150 may be configured to actuate the first (unloader) valve140 between its first and second positions. The compressor controller150 may also be configured to actuate the second (diverter) valve 142between its first and second positions. In addition, the compressorcontroller 150 may be configured to cause the compressor 130 to notcompress the gas during predetermined intervals. In other words, the gasflowing out through the outlet 134 of the compressor 130 may havesubstantially the same pressure as the gas flowing in through the inlet132 of the compressor 130 during such intervals. In one embodiment, thecompressor 130 may not compress the gas when the first valve 140 is inthe first position, and the compressor 130 may compress the gas when thefirst valve 140 is in the second position.

Referring back to the well 160, a casing 162 may be coupled to the wallof the well 160 by a layer of cement. A tubing string (e.g., aproduction string) 164 may be positioned radially-inward from the casing162. An annulus 166 may be defined between the casing 162 and the tubingstring 164. A plunger 170 may be moveable within the tubing suing 164.In some embodiments, a substantially fluid-tight seal may be formedbetween the outer surface of the plunger 170 and the inner surface ofthe tubing string 164. Optionally, a bore may be formed axially-throughthe plunger 170, and a valve 172 may be positioned within the bore. Thevalve 172 may be opened when the plunger 170 contacts a first actuator(e.g., “bumper spring”) 174 proximate to the upper end of the tubingsuing 164. The valve 172 may be closed when the plunger 170 contacts asecond actuator (e.g., “bumper spring”) 176 proximate to the lower endof the tubing string 164. In another embodiment, the plunger 170 may bea pad-type plunger.

The plunger 170 may cycle from the bottom of the well 160, to the top ofthe well 160, back to the bottom of the well 160, and so on. Moreparticularly, when the valve 172 in the plunger 170 is in the closedposition and the well 160 is producing enough gas to lift the liquid,the gas may lift the plunger 170, and the liquid that is above theplunger 170 in the tubing string 164, to the surface (e.g., when anoutlet valve is opened at the surface). As discussed in more detailbelow, when the well 160 is not producing enough gas to lift the liquidto the surface, or the well 160 is not producing enough gas to lift theliquid to the surface within a predetermined amount of time, additionalcompressed gas (e.g., from the compressor 130) may be introduced intothe well 160 to lift the plunger 170 and the liquid. When the plunger170 reaches the surface and contacts the first actuator 174, the valve172 in the plunger 170 may open, which may allow the plunger 170 todescend toward the bottom of the well 160.

When the plunger 170 reaches the bottom of the well 160 and contacts thesecond actuator 176, the valve 172 in the plunger 170 may close. Then,the gas produced in the well 160, the compressed gas introduced into thewell 160, or a combination thereof may lift the plunger 170, and theliquid that is above the plunger 170 in the tubing string 164, back tothe surface. The plunger 170 may continue to cycle up and down, liftingliquid to the surface with each trip.

The system 100 may also include wellhead equipment 177 positioned at thetopside surface of the well 170. The wellhead equipment 177 may includea sensor 178 positioned proximate to the top of the well 160 (e.g., ator near the surface). The sensor 178 may be coupled to the tubing string164, the first actuator 174, a lubricator 186 (introduced below), orother equipment at the surface. The sensor 178 may detect or sense eachtime the plunger 170 reaches the surface. In one embodiment, the sensor178 may detect or sense when the plunger 170 is within a predetermineddistance from the sensor 178. In another embodiment, the sensor 178 maydetect or sense when the plunger 170 contacts the first actuator 174and/or the lubricator 186.

In yet another embodiment, the sensor 178 may be a pressure transducerthat is coupled to and/or in fluid communication with the tubing string164, the first actuator 174, the lubricator 186, the inlet 132 of thecompressor 130, the outlet 134 of the compressor 130, or the like. Itmay be determined that the plunger 170 is at a predetermined position inthe well 160 when the pressure measured by the pressure transducer isgreater than or less than a predetermined amount. For example, a usermay open or close a valve (e.g., valve 182, 184) to cause the plunger170 to ascend or descend within the well 160. The opening or closing ofthe valve (e.g., 182, 184) may cause the pressure to increase ordecrease beyond the predetermined amount, which may be detected by thesensor 178.

In some embodiments, the system 100 may also include a wellheadcontroller 180. The wellhead controller 180 may receive the data fromthe sensor 178 and communicate with the compressor controller 150 inresponse to the data from the sensor 178, as discussed in greater detailbelow. In some embodiments, the wellhead controller 180 may track thecycle time, i.e., the time the plunger 170 takes to complete a liftingcycle in the well 160, e.g., the time the plunger 170 takes to descendfrom and rise back to a position proximal to the first actuator 174and/or the lubricator 186.

The system 100 may also include a control valve 182 and a master valve184. The wellhead controller 180 may close and open the control valve182 depending on the point in the cycle to shut-in the well 160 or allowthe well 160 to produce. The lubricator 186 may be positioned above themaster valve 184. The lubricator 186 houses a shift rod and shockabsorber to actuate the plunger 170 at the surface. Although shown asdifferent components, in another embodiment, the first actuator 174 andthe lubricator 186 may be the same component.

In some embodiments, the system 100 may also include a separator 190.The separator 190 may be configured to receive gas from the well 160.The separator 190 may separate (i.e., remove) particles from the gas toclean the gas. In at least one embodiment, the separator 190 may be agravity-based separator, such that the separation may be passive,allowing the denser solid particles to fall to the bottom of theseparator 190. The outlet of the separator 190 may be in fluidcommunication with the inlet 122 of the pressure vessel 120 and/or theinlet 132 of the compressor 130.

As mentioned above, the compressor controller 150 and the wellheadcontroller 180 may be in communication with one another. In someembodiments, the controllers 150, 180 may communicate generallycontinuously, in order to provide a status update to the other, e.g.,indicating to the other that the controller 150, 180 is online and ableto function. The controllers 150, 180 may also be able to pass controlsignals therebetween. As such, a two-way communication link 199 may beprovided between the controllers 150, 180. In some situations, thistwo-way link 199 may be representative of a wired or wirelesscommunication link. For example, the link may employ a wireless standardsuch as BLUETOOTH*. The link may be via radiofrequency, infrared,acoustic, optical, or any other transmission (e.g., telemetry) medium.The signals transmitted between the controllers 150, 180 may range fromrelatively simple (e.g., a binary off/on signal) to more complex(numbers, status, values for operating parameters, etc.), and thetransmission link therebetween may be selected to provide efficienttransmission of the given complexity of signals within a suitable amountof time. The link 199 may include one or more devices, such asrepeaters, amplifiers, conditioners, antennae, etc.

The provision of the link 199 may also enable or at least facilitateremote access to either or both of the controllers 150, 180. Forexample, a modem 198 that is capable of communicating with an externaldevice (e.g., computer at a remote terminal) may be provided on thecompressor 130 and in communication with the compressor controller 150,or vice versa. Thus, a user may remotely access the compressorcontroller 150 and then communicate with the wellhead controller 180 viathe two-way link 199. This may avoid a requirement for a powered modemto be placed at the wellhead controller 180, since power consumption maybe at a premium at this position. In other embodiments, however, a modemmay be provided at the wellhead controller 180 and not at the compressor130, so as to allow for communication from an external device to thecompressor controller 150 via the wellhead controller 180 and thetwo-way link 199. In still other embodiments, a modem may be provided atboth the compressor 130 and the wellhead controller 180, so as to, alongwith the two-way link 199, provide for redundancy in communication.

FIG. 2 illustrates a flowchart of a method 200 for operating thegas-lift plunger 170 in the well 160, according to an embodiment. Themethod 200 is described herein with reference to the system 100 in FIG.1 as a matter of convenience, but may be employed with other systems.The method 200 may begin by introducing a gas into the pressure vessel120, as at 202. The gas may be any mixture of natural gases. Asdescribed above, the gas may be introduced into the pressure vessel 120through the first inlet 122 of the pressure vessel 120. The method 200may then include removing particles from the gas using the pressurevessel 120 to produce a clean gas, as at 204. The method 200 may theninclude introducing the clean gas into the compressor 130, as at 206.

The method 200 may also include determining, using the sensor 178, whenthe plunger 170 is at a predetermined position in the well 160, as at208. In one embodiment, the predetermined position may be proximate tothe top of the well 160. In another embodiment, the predeterminedposition may be when the plunger 170 contacts the first actuator 174and/or the lubricator 186.

The sensor 178 may transmit a signal to the wellhead controller 180 eachtime the sensor 178 detects the plunger 170. The method 200 may includetransmitting a first signal from the wellhead controller 180 to thecompressor controller 150 when the plunger 170 is at the predeterminedposition, as at 210. The first signal may be transmitted through a cableor wire, or the first signal may be transmitted wirelessly. In theembodiment where the sensor 178 is a pressure transducer, the wellheadcontroller 180 may be omitted, and the sensor 178 may send a signaldirectly to the compressor controller 150 when the measured pressure isgreater than or less than the predetermined amount.

In response to receiving the first signal from the wellhead controller180 (or the signal from the sensor 178), the compressor controller 150may cause the compressor 130 to not compress the gas flowingtherethrough (i.e., “unload” the compressor 130 to provide anuncompressed gas), as at 212. In some embodiments, the uncompressed gasmay still have a pressure greater than atmospheric pressure. Theuncompressed gas may, however, have a lower pressure than the compressedgas (e.g., at 218 below). In response to receiving the first signal, thecompressor controller 150 may also actuate the first valve 140 at theoutlet 134 of the compressor 130 into the first position, as at 214,such that the uncompressed gas that exits the compressor 130 flows backinto the pressure vessel 120.

When the first valve 140 at the outlet 134 of the compressor 130 is inthe first position, and the valve 172 in the plunger 170 is open (e.g.,after contacting the first actuator 174), the plunger 170 may begindescending back to the bottom of the well 160. The uncompressed gas maycontinue to flow into the pressure vessel 120 as the plunger 170descends. The uncompressed gas may only flow into the pressure vessel120 up to the set suction pressure. The set suction pressure may be fromabout 15 psi to about 100 psi or more. The pressure vessel 120 may becertified for pressures ranging from about 100 psi to about 400 psi,about 400 psi to about 800 psi, about 800 psi to about 1200 psi, ormore. The volume of the pressure vessel 120 (provided above) may belarge enough to store the gas introduced front the compressor 130 whilethe plunger 170 descends in the well 160.

The method 200 may also include transmitting a second signal from thewellhead controller 180 to the compressor controller 150 a predeterminedamount of time after the plunger 170 is determined to be at thepredetermined position in the well 160, as at 216. The second signal maybe transmitted through a cable or wire, or the second signal may betransmitted wirelessly. In another embodiment, the compressor controller150 may have a timer set to the predetermined amount of time so that thesecond signal from the wellhead controller 180 may be omitted. Thepredetermined amount of time may be the time (or slightly more than theamount of time) that it takes for the plunger 170 to descend back to thebottom of the well 160 (e.g., to contact the second actuator 176), whichmay be known or estimated. For example, the density of the plunger 170,the density of the fluids in the well 160, and the distance between thefirst and second actuators 174, 176 may all be known or estimated. Thismay enable a user to calculate or estimate the time for the plunger 170to descend to the bottom of the well 160.

In response to receiving the second signal, the compressor controller150 may cause the compressor 130 to compress the clean gas from thepressure vessel 120 to provide a compressed gas, as at 218. In responseto receiving the second signal, the compressor controller 150 may alsoactuate the first valve 140 at the outlet 134 of the compressor 130 intothe second position, as at 220, such that the compressed gas that exitsthe compressor 130 flows into the well 160, as shown by arrows 138 inFIG. 1 . In another embodiment, the compressor controller 150 mayautomatically perform steps 218 and 220 after the predetermined amountof time, and the second signal may be omitted.

When the first valve 140 is in the second position, the compressed gasmay flow from the compressor 130, through the first valve 140, and intothe annulus 166 in the well 160. The compressed gas may then flow downthrough the annulus 166 and into the tubing string 164 at a positionbelow the plunger 170 and/or the second actuator 176. The compressed gasmay then flow up through the tubing string 164, which may lift theplunger 170 back toward the surface. The method 200 may then loop backaround to step 208. In another embodiment, an injection valve may beattached to the tubing string 164 at a location below the plunger 170and/or the second actuator 176. The compressed gas may be injectedthrough the injection valve and into the tubing string 164.

In yet another embodiment, the compressor 130 may pull (e.g., suck) onthe tubing string 164. More particularly, gas at the upper end of thetubing string 164 may be introduced into the inlet 132 of the compressor130. This may exert a force inside the tubing string 164 that pulls theplunger 170 upward. The outlet 134 of the compressor 130 may introducethe compressed gas into the annulus 166, as described above, or aportion of the compressed gas may be introduced into a sales line.

As will be appreciated, the system 100 and method 200 may control theinjection of gas from the compressor 130 on demand by “unloading” thecompressor 130 (e.g., as at 212 and/or 214) and “loading” the compressor130 (e.g., as at 218 and/or 220) in response to the detection by thesensor 178, the predetermined amount of time, or a combination thereof.The system 100 and method 200 may also stop the compressor 130 beforethe compressor 130 runs out of sufficient gas to restart. By redirectingthe gas to the pressure vessel 120 (i.e., unloading the compressor 130),the compressor 130 may avoid blowing down and/or emitting gas to theatmosphere. This is accomplished by unloading the compressor 130 backinto the pressure vessel 120 and unloading the compressor 130 so that itmay restart without any emission of gas to the atmosphere. In addition,by introducing the gas from the compressor 130 back into the pressurevessel 120, rather than releasing the gas into the atmosphere, the loudnoise generated by the release of the compressed gas may be avoided. Theenvironmental concerns caused by releasing the compressed gas into theatmosphere may also be alleviated.

FIG. 3 illustrates a flowchart of another method 300 for operating thegas-lift plunger 170 in the well 160, according to an embodiment. Themethod 300 is described herein with reference to the system 100 in FIG.1 as a matter of convenience, but may be employed with other systems.The method 300 may begin by introducing a gas into the compressor 130,as at 302. The gas may come from the pressure vessel 120 or theseparator 190 (see FIG. 1 ).

The method 300 may also include determining, using the sensor 178, whenthe plunger 170 is at a predetermined position in the well 160, as at304. In one embodiment, the predetermined position may be proximate tothe top of the well 160. In another embodiment, the predeterminedposition may be when the plunger 170 contacts the first actuator 174and/or the lubricator 186, after which time, the valve 172 is open, andthe plunger 170 begins descending.

The sensor 178 may transmit a signal to the wellhead controller 180 eachtime the sensor 178 detects the plunger 170. The method 300 may includetransmitting a first signal from the wellhead controller 180 to thecompressor controller 150, e.g., via the link 199, when the plunger 170is at the predetermined position, as at 306. The first signal may betransmitted through a cable or wire, or the first signal may betransmitted wirelessly. In the embodiment where the sensor 178 is apressure transducer, the wellhead controller 180 may be omitted, and thesensor 178 may send a signal directly to the compressor controller 150when the measured pressure is greater than or less than thepredetermined amount.

In response to receiving the first signal from the wellhead controller180 (or the signal from the sensor 178), the compressor controller 150may actuate the second valve 142 into (or maintain the second valve 142in) the first position, as at 308. When in the first position, the gasfrom the compressor is directed into the sales line 146. The third valve144 prevents the gas in the well 160 from flowing into the sales line146.

When the second valve 142 is in the first position and the valve 172 inthe plunger 170 is open (e.g., after contacting the first actuator 174and/or the lubricator 186), the plunger 170 may begin descending back tothe bottom of the well 160. The compressed gas may continue to flow intothe sales line 146 as the plunger 170 descends.

The method 300 may also include transmitting a second signal from thewellhead controller 180 to the compressor controller 150 a predeterminedamount of time after the plunger 170 is determined to be at thepredetermined position in the well 160, as at 310. The second signal maybe transmitted through a cable or wire, or the second signal may betransmitted wirelessly. In another embodiment, the compressor controller150 may have a timer set to the predetermined amount of time so that thesecond signal from the wellhead controller 180 may be omitted. Thepredetermined amount of time may be the time (or slightly more than theamount of time) that it takes for the plunger 170 to descend back to thebottom of the well 160 (e.g., to contact the second actuator 176), whichmay be known or estimated. For example, the density of the plunger 170,the density of the fluids in the well 160, and the distance between thefirst and second actuators 174, 176 may all be known or estimated. Thismay enable a user to calculate or estimate the time for the plunger 170to descend to the bottom of the well 160.

In response to receiving the second signal, the compressor controller150 may actuate the second valve 142 into the second position, as at312. In another embodiment, the compressor controller 150 mayautomatically perform the actuation at 312 after the predeterminedamount of time, and the second signal may be omitted.

When the second valve 142 is in the second position, the compressed gasmay flow from the compressor 130, through the second valve 142, and intothe annulus 166 in the well 160. A pressure of the gas flowing into thewell 160 may be substantially equal to a pressure of the gas introducedinto the sales line 146. The compressed gas may then flow down throughthe annulus 166 and into the tubing string 164 at a position below theplunger 170 and/or the second actuator 176. The compressed gas may thenflow up through the tubing string 164, which may lift the plunger 170back toward the surface. In another embodiment, an injection valve maybe attached to the tubing string 164 at a location below the plunger 170and/or the second actuator 176. The compressed gas may be injectedthrough the injection valve and into the tubing string 164.

The compressed gas and/or the gas lifted by the plunger 170 may thenflow through the valves 182, 184 and into the separator 190, as at 314.The gas may then exit the separator and flow back into the inlet 132 ofthe compressor 130, as at 316, to complete the loop. When the gasflowing out of the well 160 is introduced back into the compressor (viathe separator 190), this allows the compressor to pull (e.g., suck) onthe tubing string 164. This may exert a force inside the tubing string164 that pulls the plunger 170 upward.

The plunger 170 may continue to ascend in the well 160 during 314, 316,or both. The method 300 may then cycle back to determining when theplunger 170 is at a predetermined position in the well 160, as at 304.

FIG. 4 illustrates a flowchart of a method 400 for controlling operationof the system 100, according to an embodiment. The method 400 may beconducted by operation of the wellhead controller 180 and the compressorcontroller 150 coupled together (i.e., paired) via the link 199. In someembodiments, however, a single controller may operate to perform bothsides of the link 199, e.g., by communication with sensors positionedwhere the wellhead controller 180 and/or the compressor controller 150are described. In some embodiments, the wellhead controller 180 and thecompressor controller 150 may operate in a peer-to-peer configuration,but in others, one may be a master and may direct operation of the othercontroller, which acts as the slave. Various other configurations may beemployed.

In the illustrated embodiment, the method 400 may begin on the wellheadcontroller 180 side with the wellhead controller 180 receiving anoperation setting (e.g., cycle time), as at 402. Receiving at 402 mayoccur at initialization of the system 100, or may represent a change inthe system 100 operation enforced by a user, e.g., after the system 100has already been operating. Various operation settings may be employedinstead of or in addition to cycle time, such as pressure settings inthe case that pressure transducers are provided. In the illustratedembodiment, the wellhead controller 180 may thus be configured to trackand record the duration of the cycle of plunger travel, and may comparethe recorded duration (or other operation setting) with that received at402. In some embodiments, this may be a direct comparison, e.g., of themost recent cycle or reading, or an average or other metric of the pastseveral or more recordings.

Based on this comparison, the wellhead controller 180 may determine thatthe system 100 is not meeting the operation setting, as at 404. Forexample, the wellhead controller 180 may determine that the cycle timeis too long (i.e., not enough lift gas). In response to suchdetermination, the wellhead controller 180 may send a control signal tothe compressor controller 150 via the two-way link 199, as at 406. Thecontrol signal may be a simple binary signal, e.g., a signal at acertain, predetermined frequency. In other embodiments, the controlsignal may be more complex, and may include data representing thepresent operating characteristics of the system (e.g., the present cycletime), the amount of change of injection gas flowrate, etc.

In some embodiments, the control signal may represent a command to thecompressor controller 150. For example, the command may be to load andspeed up the compressor 130, e.g., to preset RPM and suction settings.Another command may be to unload and slow down the compressor 130 topreset RPM and suction settings. Another command may be to increase therate of compressor 130, which may be achieved by increasing the suctionpressure, if available, and otherwise increasing the compressor speed.Another command may be to decrease the rate of compressor 130 bydecreasing speed and/or suction pressure. Another command may be todivert some or all compressed gas to the casing anti/or to the salesline, which may result in modulation of the diverter and/or unloadervalves 140, 142, and/or modulation of the speed and/or suction settings.

In the meantime, the compressor controller 150 may be controlling theoperation of the compressor 130, thereby driving the system 100. Forexample, the compressor controller 150 may select a first setpoint forcompressor 130 operation, as at 450. In some embodiments, the selectionof the first setpoint may be received from a remote user, e.g.,communicating with the compressor controller 150 via a model and/or thetwo-way link 199, as discussed above. The first setpoint may beestablished based on the conditions in which the system 100 operates,e.g., including the suction pressure, compressor speed (e.g., dependingon the size and type of compressor), lift-gas requirements of the well,etc. The setpoint may include operating values for one or morecharacteristics. For example, the setpoint may include a speed of thecompressor 130, a suction pressure, a diverter and/or unloader valveposition and/or timing scheme, as discussed above. The setpoint may alsoinclude anything else relevant to the operation of the compressor 130 inthe system 100. The compressor controller 150 may thus operate thecompressor 130 (and any associated valves, e.g., at the inlet 132, thediverter valve 142, the unloader valve 140), as at 452.

As mentioned above, at some point, the wellhead controller 180 may senda control signal at 406, which the compressor controller 150 mayreceive, as at 454. The compressor controller 150 may send anacknowledgment of the receipt of the signal, as at 456, which may bereceived by the wellhead controller 180, as at 408. This may indicate tothe wellhead controller 180 that the compressor controller 150 is onlineand operational.

In response to receiving the signal at 456, the compressor controller150 may select a second setpoint for compressor operation, as at 458. Insome embodiments, the compressor controller 150 may be loaded with oneor more setpoints to select from, and may thus choose another setpoint(e.g., higher suction pressure, higher RPM, less diversion, etc.). Inother embodiments, the control signal sent by the wellhead controller180 to the compressor controller 150 at 406 may specify the newoperating parameters for the compressor 130, and thus the compressorcontroller 150 may simply give effect to these commands (e.g., acting asa slave). In still other embodiments, the wellhead controller 180 mayspecify an amount of additional gas flowrate needed, and the compressorcontroller 150 may select one among several (potentially infinite)options for the operating the compressor 130 in order to achieve thedesired flowrate.

The compressor controller 150 may then cause the compressor 130 tooperate at the second setpoint, as at 460. This may be achieved byincreasing compressor speed, opening a different pilot valve at theinlet 132 (as explained above), modulating the position of avariable—position inlet pilot valve (also mentioned above), modulatingthe position of the diverter and/or unloader valves 140, 142, or in anyother suitable manner.

The operation at the second setpoint may be transitory, e.g., totemporarily increase the injection rate of gas into the well, and aftera predetermined duration or another trigger, the compressor controller150 may be configured to resume operation of the compressor 130according to the first setpoint. In other situations, the operation atthe second setpoint may be open-ended in time, and may continue untilthe wellhead controller 180 again indicates that the system is notmeeting the operation setting.

The compressor controller 150 may, at some time, e.g., after adjustingthe operation of the compressor 130 to operate at the second setpoint,send a signal to the wellhead controller 180 via the two-way link, as at462. This signal, when received by the wellhead controller 180, as at410, may indicate to the wellhead controller 180 that the compressorcontroller 150 is online and adjusted operation of the compressor 130,as requested. The wellhead controller 180 may respond with anacknowledgment signal, as at 412, which may be received by thecompressor controller 150, as at 464. The wellhead controller 180 maythen loop back to 404, and may continue determining whether the systemis meeting the operation setting and perform the above-describedsequence in the case that the system 100 is not operating at theoperation setting. Similarly, the compressor controller 150 may loopback to 452, and may operate the compressor 130 at the selected setpoint(whether the first or second setpoint, or the first setpoint for aduration and then the second setpoint, etc.).

Accordingly, it will be seen that the system 100 is able to control theoperation of the compressor 130, including load and unloading, inresponse to plunger 170 operation, via communication with the wellheadcontroller 180. Thus, the system 100 may be able to more quickly reactto operating conditions changing, thereby reducing or eliminating theneed to purchase gas to introduce to the compressor via suction makeupvalves.

In a specific example of operation, the wellhead controller 180 mayreceive an operational setting (cycle time) of 15 minutes. The wellheadcontroller 180 may record a cycle time of 16 minutes. In response, thewellhead controller 180 may signal to the compressor controller 150 viathe two-way link 199 that the well 160 should operate at a higherinjection flowrate. The compressor controller 150, in response, maychange the rate of injection by increasing the compressor RPM and/orsuction pressure to the compressor 130, or, for machines that inject andsell, by reducing the amount of gas that is being sent to the sales lineand diverting it to the casing for injection. The compressor then sendsthe wellhead controller 180 a confirmation (acknowledgment) signal usingthe two-way link 199.

While the present teachings have been illustrated with respect to one ormore implementations, alterations and/or modifications may be made tothe illustrated examples without departing from the spirit and scope ofthe appended claims. In addition, while a particular feature of thepresent teachings may have been disclosed with respect to only one ofseveral implementations, such feature may be combined with one or moreother features of the other implementations as may be desired andadvantageous for any given or particular function. Furthermore, to theextent that the terms “including,” “includes,” “having,” “has,” “with,”or variants thereof are used in either the detailed description and theclaims, such terms are intended to be inclusive in a manner similar tothe term “comprising.” Further, in the discussion and claims herein, theterm “about” indicates that the value listed may be somewhat altered, aslong as the alteration does not result in nonconformance of the processor structure to the illustrated embodiment. Finally, “exemplary”indicates the description is used as an example, rather than implyingthat it is an ideal.

Other embodiments of the present teachings will be apparent to thoseskilled in the art from consideration of the specification and practiceof the present teachings disclosed herein. It is intended that thespecification and examples be considered as exemplary only, with a truescope and spirit of the present teachings being indicated by thefollowing claims.

What is claimed is:
 1. A method for controlling operation of a well,comprising: introducing a gas into a pressure vessel; transmitting thegas into a compressor and compressing the gas; assessing when a plungerin the well is at a first predetermined position in the well; generatinga signal from a wellhead controller when the plunger is assessed to beat the first predetermined position in the well; transmitting the signalfrom the wellhead controller to a compressor controller; receiving thesignal at the compressor controller; based at least in part uponreceiving the signal at the compressor controller, changing the speed orsuction pressure of the compressor; descending the plunger into thewell; assessing when the plunger reaches a second predetermined positionin the well; generating a second signal from the wellhead controllerafter the plunger is assessed to have reached the second predeterminedposition in the well; transmitting the second signal from the wellheadcontroller to the compressor controller; receiving the second signal atthe compressor controller; based at least in part upon receiving thesecond signal at the compressor controller, changing the speed orsuction pressure of the compressor and injecting the gas compressed bythe compressor into the well; and lifting the plunger from the secondpredetermined position in the well to the first predetermined positionin the well with the aid of the gas compressed by the compressor andinjected into the well.
 2. The method according to claim 1, wherein thegas is a mixture of natural gases.
 3. The method according to claim 1,wherein the gas is introduced into the pressure vessel through a firstinlet.
 4. The method according to claim 1, further comprising: removingparticles from the gas in the pressure vessel.
 5. The method accordingto claim 1, wherein the first predetermined position in the well is at ahighest elevation of a plunger within the well.
 6. The method accordingto claim 1, wherein the first predetermined position in the well is theplunger contacting a first actuator.
 7. The method according to claim 1,wherein the first predetermined position in the well is the plungercontacting a lubricator.
 8. The method according to claim 1, wherein thetransmitting the signal is through one of wirelessly or through a wire.9. The method according to claim 1, wherein the assessing when theplunger in the well is at the first predetermined position in the wellis through use of a sensor.
 10. The method according to claim 9, whereinthe sensor is pressure transducer.
 11. The method according to claim 1,wherein the compressed gas exits the compressor and enters an annulus ofthe well.
 12. A method for controlling operation of a well, comprising:introducing a gas into a pressure vessel; transmitting the gas into acompressor and compressing the gas; determining when a plunger in thewell is at a first predetermined position in the well; generating asignal from a wellhead controller when the plunger is at the firstpredetermined position in the well; transmitting the signal from thewellhead controller to a compressor controller; receiving the signal atthe compressor controller; based at least in part upon receiving thesignal at the compressor controller, changing the speed or suctionpressure of the compressor; descending the plunger into the well;waiting a predetermined amount of time and changing the speed or suctionpressure of the compressor and injecting the gas compressed by thecompressor into the well; and lifting the plunger from the secondpredetermined position in the well to the first predetermined positionin the well with the aid of the gas compressed by the compressor andinjected into the well.
 13. The method according to claim 12, whereinthe predetermined amount of time is determined by the compressorcontroller.
 14. The method according to claim 12, wherein the compressedgas exits the compressor and enters an annulus of the well.
 15. A methodfor controlling operation of a well, comprising: introducing a gas intoa pressure vessel; transmitting the gas into a compressor; operating thecompressor with a compressor controller at a first setpoint; receivingan operation setting at a wellhead controller; comparing the operationsetting at the wellhead controller with a recorded operation setting bythe wellhead controller; sending a control signal to the compressorcontroller from the wellhead controller; receiving the control signal atthe compressor controller, wherein the control signal contains a secondsetpoint; and altering the compressor to run at the second setpoint,wherein the sending of the control signal to the compressor controlleris performed when the operation setting and the recorded operationsetting do not agree.
 16. A method for controlling operation of a well,comprising: receiving gas at an inlet of a compressor; controlling thecompressor with a compressor controller; injecting gas compressed by thecompressor into the well to assist lifting a plunger in the well; usinga wellhead controller to assess one or more well conditions or plungerlift parameters; and sending a signal from the wellhead controller tothe compressor controller to alter operation of the compressor based onthe one or more well conditions or parameters assessed by the wellheadcontroller, wherein the altered operation of the compressor is its speedor suction pressure, and wherein one of the well conditions or plungerlift parameters is based on actual or perceived location of a plunger orplunger cycle time.
 17. The method of claim 16 further comprising:delivering compressed gas from the compressor to a diverter valve;controlling the diverter valve with the compressor controller such thatthe compressed gas is diverted to the well or to a purchase line. 18.The method of claim 17 wherein the gas received at the inlet of thecompressor is received from the well or an output of a pressure vessel,whereas in the case in which the gas is received from an output of apressure vessel, the pressure vessel includes a gas input from thecompressor and a gas input from the well.
 19. The method of claim 18wherein the compressor pulls on the well so as to pull the plungertoward the top of the well and evacuate gas from the well.
 20. Themethod of claim 19 wherein gas is injected or not injected into the wellduring specific periods, including that gas is not injected into thewell during periods when the plunger is determined to be at the top ofthe well and that gas is injected into the well during periods when theplunger is determined to be at the bottom of the well.
 21. The method ofclaim 20 wherein gas is diverted to the sales line during periods thatthe plunger is determined to be at the top of the well.
 22. The methodof claim 18 wherein the wellhead controller and the compressorcontroller are the same controller.